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BCEI > SEC Filings for BCEI > Form 10-Q on 8-Aug-2014All Recent SEC Filings

Show all filings for BONANZA CREEK ENERGY, INC.

Form 10-Q for BONANZA CREEK ENERGY, INC.


8-Aug-2014

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained in our Annual Report on Form 10-K for the year ended December 31, 2013 ("2013 Form 10-K"), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q (this "Report").

Executive Summary

Bonanza Creek Energy, Inc. ("BCEI" or, together with our consolidated subsidiaries, the "Company," "we," "us," or "our") is a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in the United States. Our predecessors were founded in 1999 and we went public in December 2011. Our shares of common stock are listed for trading on the NYSE under the symbol "BCEI."

Despite the uncertainty surrounding the global economy and volatility in commodity prices, we believe the economic returns and organic growth generated by our portfolio of oil and gas assets positions us well moving forward. Our operations are focused in the Wattenberg Field in Colorado (Rocky Mountain region) and the Dorcheat Macedonia Field in Southern Arkansas (Mid-Continent region). The low risk, oil-weighted production profile of our Arkansas assets provides a strong cash flow base from which to develop our Wattenberg Field assets, principally the Niobrara and Codell formations in Colorado. Our corporate strategy is to create shareholder value by increasing production in our current assets, while opportunistically seeking strategic acquisitions in our core areas or other high return basins across the United States where we can apply our technical competencies of horizontal drilling and fracture stimulation. We maintain a high working interest in our properties, which allows us to control the pace and magnitude of our capital spending program.

Financial and Operating Highlights

Our financial results and operational highlights for the second quarter of 2014 included:

Net income of $1.2 million (including approximately $1.3 million from continuing operations), as compared with $14.7 million (including approximately $14.9 million from continuing operations) for the second quarter of 2013. The decrease in net income is primarily due to derivative losses and compensation paid in connection with executive departures;

Total liquidity of $525.6 million, consisting of a period-end cash balance plus funds available under our credit facility, as compared with $328.1 million for the second quarter of 2013;


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Entering into a purchase and sale agreement to acquire approximately 86,000 (34,000 net) acres, leasehold mineral interests and related assets within the Wattenberg Field for $223.3 million to increase our acreage position within the region and leverage current infrastructure and operational expertise. The acquisition closed during the third quarter of 2014;

Borrowing base increase under the Revolver of $75 million to $525 million during the second quarter of 2014;

Increased production by 69% to 2,079.3 MBoe in the second quarter of 2014 from 1,227.8 MBoe in the second quarter of 2013, with oil and NGL production representing 70% of total production; and

Drilled and completed 38 gross (31.9 net) productive wells within our Rocky Mountain region and 15 gross (10.8 net) productive wells within our Mid-Continent region during the second quarter of 2014.

During the six months ended June 30, 2014, we had the following financial and operational results:

Cash flows provided by operating activities of $158.0 million, as compared with $90.8 million for the first half of 2013; and

Capital expenditures of $293.6 million, as compared with $177.4 million for the first half of 2013.

Outlook for 2014

Because the global economic outlook and commodity price environment are uncertain, we have planned a flexible capital spending program. We estimate our total capital expenditures for 2014 to be between approximately $575 million to $625 million, allocated approximately 87% to the horizontal development of the Niobrara and Codell formations in the Wattenberg Field and 13% to the vertical development of the Dorcheat Macedonia and McKamie Patton Fields in Southern Arkansas. Actual capital expenditures may fluctuate materially based on, among other things, market conditions, the success of our drilling results as the year continues to progress and changes in the borrowing base under the Revolver. This capital investment is expected to produce average production volumes of 23,000 Boe/d to 25,000 Boe/d in 2014, while maintaining a strong oil and liquids profile.

Results for Continuing Operations



Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013



The following table summarizes our revenues, sales volumes, and average sales
prices for the periods indicated.



                                                 Three Months Ended June 30,
                                                                               Percent
                                         2014          2013        Change       Change
                                             (In thousands, except percentages)
Revenues:
Crude oil sales                       $   127,444    $  71,172    $  56,272          79 %
Natural gas sales                          19,734        9,448       10,286         109 %
Natural gas liquids sales                   4,504        3,893          611          16 %
CO2 sales                                       -            4           (4 )      (100 )%
Product revenue                       $   151,682    $  84,517    $  67,165          79 %

Sales Volumes:
Crude oil (MBbls)                         1,376.3        796.0        580.3          73 %
Natural gas (MMcf)                        3,697.1      2,114.4      1,582.7          75 %
Natural gas liquids (MBbls)                  86.8         79.4          7.4           9 %
Crude oil equivalent (MBoe)(1)            2,079.3      1,227.8        851.5          69 %

Average Sales Prices (before
derivatives)(2)
Crude oil (per Bbl)                   $     92.60    $   89.41    $    3.19           4 %
Natural gas (per Mcf)                 $      5.34    $    4.47    $    0.87          19 %
Natural gas liquids (per Bbl)         $     51.89    $   49.03    $    2.86           6 %
Crude oil equivalent (per Boe)(1)     $     72.95    $   68.83    $    4.12           6 %

Average Sales Prices (after
derivatives)(2)
Crude oil (per Bbl)                   $     88.31    $   87.41    $    0.90           1 %
Natural gas (per Mcf)                 $      5.33    $    4.52    $    0.81          18 %
Natural gas liquids (per Bbl)         $     51.89    $   49.03    $    2.86           6 %
Crude oil equivalent (per Boe)(1)     $     70.10    $   67.62    $    2.48           4 %


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(1) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. Excludes CO2 sales.

(2) The derivatives economically hedge the price we receive for crude oil and natural gas.

Revenues increased by 79%, to $151.7 million for the three months ended June 30, 2014 compared to $84.5 million for the three months ended June 30, 2013 due to the increase in oil, natural gas, and natural gas liquids production of 73%, 75%, and 9%, respectively, for the comparable periods. The increased volumes are a direct result of the $269.7 million expended for drilling and completion during the last six months of 2013 and the $293.6 million expended during the six months ended June 30, 2014. During the period from June 30, 2013 through June 30, 2014, we drilled and completed 102 gross (91.8 net) wells in the Rocky Mountain region and 47 gross (36.2 net) wells in the Mid-Continent region. Our Wattenberg Field natural gas is sold as wet gas without processing into dry gas and NGLs, and therefore, sells at a premium due to its high BTU content.

The following table summarizes our operating expenses for the periods indicated.

                                                   Three Months Ended June 30,
                                                                               Percent
                                              2014         2013      Change    Change
                                               (In thousands, except percentages)
Expenses:
Lease operating                            $    18,018   $ 12,898   $  5,120        40 %
Severance and ad valorem taxes                  16,263      5,352     10,911       204 %
Exploration                                         96        862       (766 )     (89 )%
Depreciation, depletion and amortization        54,117     29,517     24,600        83 %
General and administrative                      24,547     13,283     11,264        85 %
Operating expenses                         $   113,041   $ 61,912   $ 51,129        83 %

Selected Costs ($ per Boe):
Lease operating                            $      8.67   $  10.50   $  (1.83 )     (17 )%
Severance and ad valorem taxes                    7.82       4.36       3.46        79 %
Exploration                                       0.05       0.70      (0.65 )     (93 )%
Depreciation, depletion and amortization         26.03      24.04       1.99         8 %
General and administrative                       11.81      10.82       0.99         9 %
Operating expenses                         $     54.38   $  50.42   $   3.96         8 %

Lease Operating Expense. Our lease operating expenses increased $5.1 million, or 40%, to $18.0 million for the three months ended June 30, 2014 from $12.9 million for the three months ended June 30, 2013 and decreased on an equivalent basis from $10.50 per Boe to $8.67 per Boe. The aggregate increase in lease operating expenses was related to increased production volumes attributable to our drilling program. During the quarter ended June 30, 2014, three of the largest components of lease operating expenses were well servicing, compression, and pumping which increased $1.8 million, $1.8 million and $756,000, respectively, over the comparable period in 2013. The decrease in lease operating expenses on an equivalent basis was primarily related to higher production from our horizontal wells in the Wattenberg Field.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased $10.9 million, or 204%, to $16.3 million for the three months ended June 30, 2014 from $5.4 million for the three months ended June 30, 2013. The increase was primarily related to a 69% increase in production volumes during the three months ended June 30, 2014 over the comparable period in 2013. Colorado has higher severance and ad valorem tax rates than Arkansas and contributed a greater percentage of production for the three months ended June 30, 2014 when compared to the same period in 2013. In addition, our increase in new production during 2013 in the Wattenberg Field resulted in a higher than expected lag in the amount of ad valorem tax credits eligible for deduction against severance taxes generated in the current year because ad valorem taxes are not eligible for deduction the first year a well is completed.

Exploration costs. Our exploration expense decreased $766,000 to $96,000 during the three months ended June 30, 2014 from $862,000 for the three months ended June 30, 2013. During the three months ended June 30, 2013 a seismic acquisition project in the Wattenberg Field was completed which resulted in charges of approximately $700,000. We did not complete any material seismic acquisitions during the three months ended June 30, 2014.


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Depreciation, depletion and amortization. Our depreciation, depletion, and amortization expense increased $24.6 million, or 83%, to $54.1 million for the three months ended June 30, 2014 from $29.5 million for the three months ended June 30, 2013. Our depreciation, depletion and amortization expense per Boe increased $1.99, or 8% to $26.03 for the three months ended June 30, 2014 as compared to $24.04 for the three months ended June 30, 2013. This increase was primarily the result of a significant increase in productive assets with a proved reserve rate increase of 27% period over period and a proved developed reserve rate increase of 12% period over period.

General and administrative. Our general and administrative expense increased $11.3 million, or 85%, to $24.6 million for the three months ended June 30, 2014 from $13.3 million for the comparable period ended June 30, 2013 and increased on an equivalent basis to $11.81 per Boe from $10.82 per Boe. During the three months ended June 30, 2014, wages and benefits and stock-based compensation were $6.3 million and $4.7 million higher, respectively, than the same period in 2013. The increases in wages and benefits and a portion of stock-based compensation are due to an increase in headcount as a result of our accelerated drilling program between the three month periods ended June 30, 2014 and 2013. The majority of the increase in general and administrative expense on an equivalent basis was related to executive departures which resulted in charges for cash severance and stock-based compensation of $2.9 million and $3.7 million, respectively.

Derivative gain (loss). Our derivative loss increased $34.9 million to $27.3 million for the three month period ended June 30, 2014 from a $7.6 million gain for the comparable period in 2013. The loss incurred was primarily the result of realized prices being greater than the contract prices. Please refer to Note 10
- Derivatives above for additional discussion.

Interest expense. Our interest expense for the three months ended June 30, 2014 increased $3.5 million, or 59%, to $9.4 million compared to $5.9 million for the three months ended June 30, 2013. The increase for the three months ended June 30, 2014 is primarily due to the issuance of the add-on of $200 million of 6.75% Senior Notes during the fourth quarter of 2013. Interest expense, including amortization of the premium and financing costs, on the 6.75% Senior Notes for the three month periods ended June 30, 2014 and 2013 was $8.5 million and $4.8 million, respectively. Average debt outstanding for the three months ended June 30, 2014 was $500.0 million as compared to $292.5 million for the comparable period in 2013.

Income tax expense. Our estimate for federal and state income taxes for the three months ended June 30, 2014 was $800,000 from continuing operations as compared to $9.3 million for the three months ended June 30, 2013. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rate for the three month periods ended June 30, 2014 and 2013 was 38.5%, which differs from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013



The following table summarizes our revenues, sales volumes, and average sales
prices for the periods indicated.



                                                 Six Months Ended June 30,
                                                                             Percent
                                        2014         2013        Change       Change
                                            (In thousands, except percentages)
Revenues:
Crude oil sales                       $ 231,191    $ 136,849    $  94,342          69 %
Natural gas sales                        38,249       18,028       20,221         112 %
Natural gas liquids sales                 9,630        7,882        1,748          22 %
CO2 sales                                     7           66          (59 )       (89 )%
Product revenue                       $ 279,077    $ 162,825    $ 116,252          71 %

Sales Volumes:
Crude oil (MBbls)                       2,540.6      1,521.2      1,019.4          67 %
Natural gas (MMcf)                      6,786.3      3,960.5      2,825.8          71 %
Natural gas liquids (MBbls)               180.8        154.1         26.7          17 %
Crude oil equivalent (MBoe)(1)          3,852.4      2,335.4       1517.0          65 %

Average Sales Prices (before
derivatives)(2)
Crude oil (per Bbl)                   $   91.00    $   89.96    $    1.04           1 %
Natural gas (per Mcf)                 $    5.64    $    4.55    $    1.09          24 %
Natural gas liquids (per Bbl)         $   53.26    $   51.15    $    2.11           4 %
Crude oil equivalent (per Boe)(1)     $   72.44    $   69.69    $    2.75           4 %

Average Sales Prices (after
derivatives)(2)
Crude oil (per Bbl)                   $   88.01    $   87.83    $    0.18           0 %
Natural gas (per Mcf)                 $    5.56    $    4.62    $    0.94          20 %
Natural gas liquids (per Bbl)         $   53.26    $   51.15    $    2.11           4 %
Crude oil equivalent (per Boe)(1)     $   70.33    $   68.41    $    1.92           3 %


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(1) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. Excludes CO2 sales.

(2) The derivatives economically hedge the price we receive for crude oil and natural gas.

Revenues increased by 71%, to $279.1 million for the six months ended June 30, 2014 compared to $162.8 million for the six months ended June 30, 2013 due primarily to the increase in oil, natural gas, and natural gas liquids production of 67%, 71%, and 17%, respectively, for the comparable periods. An increase in average sales price on an equivalent basis of 4% for the six months ended June 30, 2014 when compared to the same period in 2013 also contributed to the increase in revenues. Please refer to Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013 above for additional discussion.

The following table summarizes our operating expenses for the periods indicated.

                                                    Six Months Ended June 30,
                                                                               Percent
                                              2014        2013       Change    Change
                                               (In thousands, except percentages)
Expenses:
Lease operating                            $   35,099   $  24,029   $ 11,070        46 %
Severance and ad valorem taxes                 27,013      10,165     16,848       166 %
Exploration                                     1,179       1,424       (245 )     (17 )%
Depreciation, depletion and amortization       95,248      52,880     42,368        80 %
General and administrative                     48,261      26,449     21,812        82 %
Operating expenses                         $  206,800   $ 114,947   $ 91,853        80 %

Selected Costs ($ per Boe):
Lease operating                            $     9.11   $   10.29   $  (1.18 )     (11 )%
Severance and ad valorem taxes                   7.01        4.35       2.66        61 %
Exploration                                      0.31        0.61      (0.30 )     (49 )%
Depreciation, depletion and amortization        24.72       22.64       2.08         9 %
General and administrative                      12.53       11.33       1.20        11 %
Operating expenses                         $    53.68   $   49.22   $   4.46         9 %

Lease Operating Expense. Our lease operating expenses increased $11.1 million, or 46%, to $35.1 million for the six months ended June 30, 2014 from $24.0 million for the six months ended June 30, 2013 and decreased on an equivalent basis from $10.29 per Boe to $9.11 per Boe. The aggregate increase in lease operating expenses was related to increased production volumes attributable to our drilling program. During the six months ended June 30, 2014, three of the largest components of lease operating expenses were well servicing, compression, and pumping which increased $5.3 million, $2.7 million and $1.9 million, respectively, over the comparable period in 2013. The decrease in lease operating expenses on an equivalent basis was primarily related to higher production from our horizontal wells in the Wattenberg Field.

Severance and ad valorem taxes. Our severance and ad valorem taxes increased $16.8 million, or 166%, to $27.0 million for the six months ended June 30, 2014 from $10.2 million for the six months ended June 30, 2013. The increase was primarily related to a 65% increase in production volumes during the six months ended June 30, 2014 over the comparable period in 2013. Please refer to Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013 above for additional discussion.

Exploration costs. Our exploration expense decreased $245,000 to $1.2 million during the six months ended June 30, 2014 from $1.4 million for the six months ended June 30, 2013. During the six months ended June 30, 2014, we incurred a $1.0 million dry hole charge related to a vertical well within the Wattenberg Field drilled to test the Lyons formation. During the six months ended June 30, 2013 a seismic acquisition project in the Wattenberg Field was completed which resulted in charges of approximately $1.0 million.


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Depreciation, depletion and amortization. Our depreciation, depletion, and amortization expense increased $42.3 million, or 80%, to $95.2 million for the six months ended June 30, 2014 from $52.9 million for the six months ended June 30, 2013. Our depreciation, depletion and amortization expense per Boe increased $2.08, or 9% to $24.72 for the six months ended June 30, 2014 as compared to $22.64 for the six months ended June 30, 2013. This increase is primarily due to a larger increase in production of 65% versus the corresponding increase in proved developed reserves of 33%.

General and administrative. Our general and administrative expense increased $21.8 million, or 82%, to $48.3 million for the six months ended June 30, 2014 from $26.5 million for the comparable period in 2013 and increased on an equivalent basis to $12.53 per Boe from $11.33 per Boe. During the six months ended June 30, 2014, wages and benefits and stock-based compensation were $13.1 million and $7.1 million higher, respectively, than the same period in 2013. The majority of increase in general and administrative expense on an equivalent basis was related to executive departures which resulted in charges for cash severance and stock-based compensation of $6.5 million and $7.6 million, respectively. Please refer to Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013 above for additional discussion.

Derivative gain (loss). Our derivative loss increased $38.5 million to $36.1 million for the six month period ended June 30, 2014 from a $2.4 million gain for the comparable period in 2013. The loss incurred was primarily the result of realized prices being greater than the contract prices. Please refer to Note 10
- Derivatives above for additional discussion.

Interest expense. Our interest expense for the six months ended June 30, 2014 increased $11.0 million, or 141%, to $18.8 million compared to $7.8 million for the six months ended June 30, 2013. The increase for the six months ended June 30, 2014 is primarily due to the issuance of the add-on of $200 million of 6.75% Senior Notes during the fourth quarter of 2013. Interest expense, including amortization of the premium and financing costs, on the 6.75% Senior Notes for the six month periods ended June 30, 2014 and 2013 was $17.1 million and $4.8 million, respectively. Interest expense on the Revolver was $2.6 million during the six month period ended June 30, 2013. Average debt outstanding for the six months ended June 30, 2014 was $500 million as compared to $235.8 for the comparable period in 2013.

Income tax expense. Our estimate for federal and state income taxes for the six months ended June 30, 2014 was $6.8 million from continuing operations as compared to $16.4 million for the six months ended June 30, 2013. Our effective tax rate for the six month periods ended June 30, 2014 and 2013 was 38.5%. Please refer to Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013 above for additional discussion.

Results for Discontinued Operations

During June 2012, the Company began marketing, with intent to sell, all of its oil and gas properties in California. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. The Company determined that our intent to exit an entire region qualified for discontinued operations accounting and these assets have been presented as discontinued operations in the accompanying statements of operations.

The majority of these properties were sold in 2012. The remaining property located in the Midway Sunset Field sold on March 21, 2014 for approximately $6.0 million and resulted in a $6.3 million gain. Please refer to Note 4 - Discontinued Operations for additional discussion.

There were no operating results for our California properties for the three months ended June 30, 2014. Revenues and operating expenses for the same properties for the three months ended June 30, 2013 were $437,000 and $711,000, respectively. Sales volumes for the three month period ended June 30, 2013 were 51 Boe per day.

Revenues and operating expenses for the California properties for the six months ended June 30, 2014 and 2013 were $361,000 and $446,000, respectively, and $875,000 and $1.2 million, respectively. Sales volumes for the six month periods ended June 30, 2014 and 2013 were 20 Boe per day and 50 Boe per day.

Liquidity and Capital Resources

We fund our operations, capital expenditures and working capital requirements with cash flows from our operating activities and borrowings under our revolving credit facility. Periodically, we access debt and capital markets and sell non-core properties to provide additional liquidity.

We believe that our cash on hand, cash flow from operating activities and availability under our revolving credit facility will be sufficient to fund our planned capital expenditures and operating expenses and comply with our debt covenants for at least the next 12 months. To the extent actual operating results differ from our anticipated results our liquidity could be adversely affected.


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On May 15, 2014, our borrowing base under the Revolver was increased to $525 million from $450 million. We elected to limit bank commitments to $400 million while reserving the option to access, at the Company's request, the full $525 million. As of June 30, 2014, we had nil outstanding on our credit facility, $36 million of letters of credit issued, and $489 million available borrowing capacity. Our weighted-average interest rate (excluding amortization of deferred . . .

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